利用碳酸盐岩岩心开展岩心驱替实验,研究了在智能水驱过程中由于矿物结垢沉淀而引起的储集层伤害风险以及注入水矿化度和离子组成对矿物结垢沉淀的影响。设计了一种新的室内岩心驱替实验程序以模拟注入水和地层水在储集层中的流动条件,考虑了注入水和地层水的原位接触时间对矿物结垢沉淀的影响。在确定了最佳接触时间之后,通过改变注入海水的矿化度和离子浓度来研究渗透率下降程度的变化。利用扫描电镜对结垢后的岩心样品进行目测分析,以研究结垢晶体形态。实验结果表明,在设定的实验条件下,CaSO4和CaCO3复合结垢沉淀导致的渗透率下降幅度为初始渗透率的61.0%~79.1%,注入智能水的矿化度、离子组成以及注入水与地层水的接触时间对CaSO4和CaCO3结垢沉淀有显著影响。扫描电镜图像显示,岩心渗透率的损失主要是由结垢晶体积聚并垂直于孔隙壁面生长造成的。图11表5参33
This work was conducted to study the risk of formation damage as the result of mineral scales deposition during smart waterflooding into carbonate core sample, as well as the influence of injected water salinity and ionic composition on mineral scaling and precipitation. The reservoir flowing conditions were simulated by a new laboratory core-flooding procedure, which took into count of the effect of in-situ contact time (CT) of injected water and formation water on scaling. After the optimum CT was determined, extent of permeability decline was studied by the change in the salinity and ionic composition of injection seawater. The scaled core sample was analyzed visually by scanning electron microscopy (SEM) to study the crystal morphology of the scale. Under the experimental conditions, extent of permeability decline caused by CaSO4 and CaSO3 composite scales ranged from 61% to 79.1% of the initial permeability. The salinity and the ionic composition of injected smart water, and CT of the mixing waters had significant effects on the co-precipitation of CaSO4 and CaSO3 scales. The SEM images reveal that the loss of permeability is mainly caused by the accumulation and growth perpendicular to the pore wall of scale crystals.
[1] KORRANI K N.Mechanistic modeling of low salinity water injection[D]. Texas: University of Texas at Austin, 2014.
[2] AL SHALABI E W, SEPEHRNOORI K, DELSHAD M. Mechanisms behind low salinity water injection in carbonate reservoirs[J]. Fuel, 2014, 121(4): 11-19.
[3] YOUSEF A A, AL-SALEH S, AL-KAABI A U, et al. Laboratory investigation of novel oil recovery method for carbonate reservoirs[R]. Calgary: Canadian Unconventional Resources and International Petroleum Conference, 2010.
[4] ZHANG P, TWEHEYO M T, AUSTAD T.Wettability alteration and improved oil recovery by spontaneous imbibition of seawater into chalk: Impact of the potential determining ions Ca2+, Mg2+, and SO42-[J]. Colloids and Surfaces A: Physicochemical and Engineering Aspects, 2007, 301(1/2/3): 199-208.
[5] AL-ATTAR H H, MAHMOUD M Y, ZEKRI A Y. Low-salinity flooding in a selected carbonate reservoir: Experimental approach[R]. SPE 164788x-MS, 2013.
[6] AWOLAYO A, SARMA H, ALSUMAITI A M.A laboratory study of ionic effect of smart water for enhancing oil recovery in carbonate reservoirs[R]. SPE 169662-MS, 2014.
[7] SOHAL M A, THYNE G, SØGAARD E G. Review of recovery mechanisms of ionically modified waterflood in carbonate reservoirs[J]. Energy & Fuels, 2016, 30(3): 1904-1914.
[8] AFEKAR D A, RADONJIC M.From mineral surfaces and coreflood experiments to reservoir implementations: Comprehensive review of low-salinity water flooding (LSWF)[J]. Energy & Fuels, 2017, 31(12): 13043-13062.
[9] FATHI S J, AUSTAD T, STRAND S.Water-based enhanced oil recovery (EOR) by “smart water”: Optimal ionic composition for EOR in carbonates[J]. Energy & Fuels, 2011, 25(11): 5173-5179.
[10] MEHRABAN M F, AYATOLLAHI S, SHARIFI M.Role of divalent ions, temperature, and crude oil during water injection into dolomitic carbonate oil reservoirs[J]. Oil & Gas Science and Technology, 2019, 74(5): 36.
[11] ROSTAMI P, MEHRABAN M F, SHARIFI M, et al.Effect of water salinity on oil/brine interfacial behaviour during low salinity waterflooding: A mechanistic study[J]. Petroleum, 2019, 5: 367-374.
[12] MOKHTARI R, AYATOLLAHI S, FATEMI M.Experimental investigation of the influence of fluid-fluid interactions on oil recovery during low salinity water flooding[J]. Journal of Petroleum Science and Engineering, 2019, 182: 106194.
[13] MEHRABAN M F, AFZALI S, AHMADI Z, et al.Smartwater flooding in a carbonate asphaltenic fractured oil reservoir: Comprehensive fluid-fluid-rock mechanistic study[R]. Stavanger, Norway: IOR 2017-19th European Symposium on Improved Oil Recovery, 2017.
[14] ZHANG P, AUSTAD T.Wettability and oil recovery from carbonates: Effects of temperature and potential determining ions[J]. Colloids and Surfaces A: Physicochemical and Engineering Aspects, 2006, 279(1/2/3): 179-187.
[15] MOHANTY K K, CHANDRASEKHAR S.Wettability alteration with brine composition in high temperature carbonate reservoirs[R]. SPE 166280, 2013.
[16] BINMERDHAH A B, YASSIN A A M, MUHEREI M A. Laboratory and prediction of barium sulfate scaling at high-barium formation water[J]. Journal of Petroleum Science and Engineering, 2010, 70(1/2): 79-88.
[17] JAMIALAHMADI M, MULLER-STEINHAGEN H.Mechanisms of scale deposition and scale removal in porous media[J]. International Journal of Oil, Gas and Coal Technology, 2008, 1(1/2): 81-108.
[18] VOLOSHIN A, RAGULIN V, TYABAYEVA N, et al.Scaling problems in western Siberia[R]. SPE 80407, 2003.
[19] MOGHADASI J, JAMIALAHMADI M, MÜLLER-STEINHAGEN H, et al. Scale formation in Iranian oil reservoir and production equipment during water injection[R]. Aberdeen: SPE International Symposium on Oilfield Scale, 2003.
[20] PAULO J, MACKAY E, MENZIES N, et al.Implications of brine mixing in the reservoir for scale management in the alba field[R]. SPE 68310-MS, 2001.
[21] GRAHAM G, BOAK L, HOBDEN C.Examination of the effect of generically different scale inhibitor species (PPCA and DETPMP) on the adherence and growth of barium sulphate scale on metal surfaces[R]. SPE 68298-MS, 2001.
[22] MOGHADASI J, SHARIF A, MÜULLER-STEINHAGEN H, et al. Prediction of scale formation problems in oil reservoirs and production equipment due to injection of incompatible waters[J]. Developments in Chemical Engineering and Mineral Processing, 2006, 14: 545-566.
[23] MOGHADASI J, JAMIALAHMADI M, MÜLLER-STEINHAGEN H, et al. Scale formation in oil reservoir and production equipment during water injection: Kinetics of CaSO4 and CaCO3 crystal growth and effect on formation damage[R]. SPE 82233-MS, 2003.
[24] TAHMASEBI H A, KHARRAT R, SOLTANIEH M.Dimensionless correlation for the prediction of permeability reduction rate due to calcium sulphate scale deposition in carbonate grain packed column[J]. Journal of the Taiwan Institute of Chemical Engineers, 2010, 41(3): 268-278.
[25] MERDHAH A, YASSIN A.Formation damage due to scale formation in porous media resulting water injection[J]. System, 2008, 14: 15.
[26] MOHAMMADI M, RIAHI S.Experimental investigation of water incompatibility and rock/fluid and fluid/fluid interactions in the absence and presence of scale inhibitors[R]. SPE 201117-PA, 2020.
[27] KAN A, TOMSON M.Scale prediction for oil and gas production[J]. SPE Journal, 2012, 17: 362-378.
[28] MACKAY E, GRAHAM G.The use of flow models in assessing the risk of scale damage[R]. SPE 80252-MS, 2003.
[29] MOGHADASI J, TALAEI A.Experimental investigation of prediction and inhibition of sulfate scales[D]. Ahvaz, Iran: Petroleum University of Technology, 2012.
[30] NASERI S, MOGHADASI J, JAMIALAHMADI M.Effect of temperature and calcium ion concentration on permeability reduction due to composite barium and calcium sulfate precipitation in porous media[J]. Journal of Natural Gas Science and Engineering, 2015, 22: 299-312.
[31] GHASEMIAN J, RIAHI S, AYATOLLAHI S, et al.Effect of salinity and ion type on formation damage due to inorganic scale deposition and introducing optimum salinity[J]. Journal of Petroleum Science and Engineering, 2019, 177: 270-281.
[32] MCELHINEY J E, SYDANSK R D, LINTELMANN K A, et al.Determination of in-situ precipitation of barium sulphate during coreflooding[R]. SPE 68309-MS, 2001.
[33] TODD A C, YUAN M.Barium and strontium sulfate solid solution formation in relation to north sea scaling problems[R]. SPE 19762-PA, 1990.
